1. Field of the Invention
This invention relates to an improved method and apparatus for drilling a well beneath a body of water. More particularly, the invention relates to a method and apparatus for maintaining a controlled hydrostatic pressure in a drilling riser.
2. Description of the Prior Art
In recent years the search for oil and natural gas has extended into deep waters overlying the continental shelves. In deep waters it is common practice to conduct drilling operations from floating vessels or from tall bottom-supported platforms. The floating vessel or platform is stationed over a wellsite and is equipped with a drill rig and associated equipment. To conduct drilling operations from a floating vessel or platform a large diameter riser pipe is employed which extends from the surface down to a subsea wellhead on the ocean floor. The drill string extends through the riser into blowout preventers positioned atop the wellhead. The riser pipe serves to guide the drill string and to provide a return conduit for circulating drilling fluids.
An important function performed by the drilling fluids is well control. The column of drilling fluid contained within the wellbore and the riser pipe exerts hydrostatic pressure on the subsurface formation which overcomes formation pressures and prevents the influx of formation fluids. However, if the column of drilling fluid exerts excessive hydrostatic pressure, the reverse problem can occur, i.e., the pressure of the fluid can exceed the natural fracture pressure of one or more of the formations. Should this occur, the hydrostatic pressure of the drilling fluid could initiate and propogate a fracture in the formation, resulting in fluid loss to the formation, a condition known as "lost circulation". Excessive fluid loss to one formation can result in loss of well control in other formations being drilled, thereby greatly increasing the risk of a blowout.
The problem of lost circulation is particularly troublesome in deep waters where the fracture pressure of shallow formations, especially weakly consolidated sedimentary formations, does not significantly exceed that of the overlying column of seawater. A column of drilling fluid, normally weighted by drill cuttings and various additives such as bentonite, need be only slightly more dense than seawater to exceed the fracture pressure of these formations. Therefore, to minimize the possibility of lost circulation caused by formation fracture while maintaining adequate well control, it is necessary to control the hydrostatic pressure within the riser pipe.
There have been various approaches to controlling the hydrostatic pressure of the returning drilling fluid. One approach is to reduce the drill cuttings content of the drilling fluid in order to decrease the density of the drilling fluid. That has been done by increasing drilling fluid circulation rates or decreasing drill bit penetration rates. Each of these techniques is subject to certain difficulties. Decreasing the penetration rate requires additional expensive rig time to complete the drilling operation. This is particularly a problem offshore where drilling costs are several times more expensive than onshore. Inceasing the circulation rate is also an undesirable approach since increased circulation requires additional pumping capacity and may lead to erosion of the wellbore.
Another approach in controlling hydrostatic pressure is to inject gas into the lower end of the riser. Gas injected into the riser intermingles with the returning drilling fluid and reduces the density of the fluid. An example of a gas injection system is disclosed in U.S. Pat. No. 3,815,673 (Bruce et al) wherein an inert gas is compressed, transmitted down a separate conduit, and injected at various points along the lower end of the drilling riser. The patent also discloses a control system responsive to the hydrostatic head of the drilling fluid which controls the rate of gas injection in the riser in order to maintain the hydrostatic pressure at a desired level. Such control systems, however, have the disadvantage of inherent time lags which can result in instability. This is especially a problem in very deep water where there may be significant delays from the time a control signal is initiated to the time a change in gas rate can produce a change in the pressure at the lower end of the riser pipe. As a result, the gas lift systems disclosed in the prior art do not have predictable responses with changing conditions.